1. Field of Invention
The present invention relates generally to methods for stimulating hydrocarbon-bearing formations, i.e., to increase the production of hydrocarbon oil and/or gas from the formation and more particularly, to methods for monitoring fluid placement during matrix treatments. The invention also relates to increasing injectivity of an injector.
2. Related Art
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation and thus causing a pressure gradient that forces the fluid to flow from the reservoir to the well. Often, well production is limited by poor permeability either due to naturally tight formations or due to formation damages typically arising from prior well treatment, such as drilling.
To increase the net permeability of a reservoir, it is common to perform a well stimulation treatment. A common stimulation technique consists of injecting an acid that reacts with and dissolves the formation damage or a portion of the formation thereby creating alternative flow paths for the hydrocarbons to migrate through the formation to the well. This technique known as acidizing (or more generally as matrix stimulation) may eventually be associated with fracturing if the injection rate and pressure is enough to induce the formation of a fracture in the reservoir.
Fluid placement is critical to the success of stimulation treatments. Natural reservoirs are often heterogeneous; the fluid will preferentially enter areas of higher permeability in lieu of entering areas where it is most needed. Each additional volume of fluid follows the path of least resistance, and continues to invade in zones that have already been treated. Therefore, it is difficult to place the treating fluids in severely damaged and lower permeability zones.
In order to control placement of treating fluids, various techniques have been employed. Mechanical techniques involve for instance the use of ball sealers and packers and of coiled tubing placement to specifically spot the fluid across the zone of interest. Non-mechanical techniques typically make use of gelling agents as diverters for temporarily impairing the areas of higher permeability and increasing the proportion of the treating zone that goes into the areas of lower permeability.
Therefore, for evaluation and optimization of matrix treatments it is of interest to measure the placement of treating fluids. The present invention determines fluid placement in the reservoir by the measurement and interpretation of one or more of temperature, pressure, and flow rate of fluids injected into the wellbore and close to the fluid exit from an oilfield tubular, such as coiled tubing, using special diagnostic plots.
Some techniques have been proposed for tracking fluid movement in the wellbore such as temperature measurements, spinners and logging devices (for example gamma ray logs) used in combination with radioactive tracers in the fluids. Temperature measurement technologies have focused mainly on an array of temperature sensors (see published U.S. Patent Application Number 20040129418 A1) that allows one to obtain real time temperature profiles for interpretation to support the decision making and/or design modification process. To acquire the temperature profile, the current practice is to maintain the CT/optical fiber sensors stationary in the well to allow the well to stabilize, before taking a “snap shot” of the temperature profile of the well.
Published Patent Applications US20050263281, WO2005116388, US20050236161 and WO2005103437 describe technology to communicate between downhole sensors and the surface to enable real time decision making based on accurate (0.01% accuracy) bottomhole pressure and temperature (1% accuracy) gauges. The technologies outlined in these documents are primarily directed to the measurement and telemetry but not interpretation of the measured data.
The main problems with conventional stimulation/fluid diversion methods and systems are that interpretation of the measurements, whether gathered in realtime or delayed, may be difficult. In most cases, interpretation will come hours after the data is collected. If the telemetry system is not hardwired to the surface, the delay time/data time to the surface also becomes a hardship on timing for interpretation. Another problem with conventional stimulation diversion processes and systems is that the measurements were not designed to provide a qualitative answer to the service that is being performed. One of the many services is flow diversion of fluid into a reservoir section of a well. Another problem with conventional stimulation diversion processes and systems is that they were never designed to run on the end of oilfield tubulars such as coiled tubing. This is especially true for the logging tool flow meters which are designed to be run on the end of cable. This makes them vulnerable to damage. Existing systems also typically use a wired cable in the coiled tubing that increases weight while decreasing reliability.
From the above it is evident that there is a need in the art for new methods and new tools to perform the methods that allow monitoring of fluid placement in hydrocarbon-bearing reservoirs in real time.